Drilling is a challenging task anywhere you go today, but drilling in the Arctic is exponentially more demanding and costly. To get a sense of what operations are like in an arctic environment, Parker Drilling’s Bryan Collins, VP – Arctic operations, explained a typical day...

Big risks, bigger rewards?

High-cost Arctic exploration faces increasing competition for investment dollars, but potential for monster fields still lures those who dare

By Katherine Scott, associate editor

Nabors’ Rig 520 operates near Usinsk, a city in the Komi Republic of Russia. Russia’s Ministry of Natural Resources has estimated in-country Arctic resources at 75 billion tons of oil equivalent, with 70% of it being gas and 30% oil.

Drilling is a challenging task anywhere you go today, but drilling in the Arctic is exponentially more demanding and costly. To get a sense of what operations are like in an arctic environment, Parker Drilling’s Bryan Collins, VP – Arctic operations, explained a typical day. “In February, one of our new arctic rigs in Alaska embarked on its initial rig move to our client’s first well location on the North Slope. The journey was inordinately difficult due to -40°F ambient temperatures (-60°F wind chill) and frozen roads, marked only by delineators, across an all-white tundra landscape with limited visibility.

“During the move, spotters walked alongside the outside of the rig acting as ‘eyes’ for the rig module drivers. Spotters must rotate in and out of the crew van every 10 minutes in order to limit their exposure to the extreme environment. It takes a special kind of person willing to work in these types of conditions and an intense focus on training to ensure safe operations.”

Despite such challenging environments, companies are steering toward the Arctic frontier in hopes of finding and extracting additional resources in remote and harsh environments. Although this means significant cost increases compared with other hydrocarbon provinces around the world, the possibility of finding untouched reserves can be enough to make the Arctic an attractive prospect. Through rig enhancements and technologies such as extended-reach drilling, industry is slowly pushing its way north into remote territories.

Jurisdictionally, the Arctic includes portions of eight countries – Canada, Denmark (Greenland), Finland, Iceland, Norway, Russia, Sweden and the United States. According to a 2009 report from the US Energy Information Administration, the most recent available, approximately 61 large oil and natural gas fields have been discovered within the Arctic Circle. These are fields that exceed 500 million barrels of oil equivalent recoverable oil and natural gas: 43 in Russia, 11 in Canada, six in Alaska and one in Norway. Large Arctic discoveries began in Russia with the Tazovskoye Field in 1962 and in the US with Alaska’s Prudhoe Bay in 1967.

In its “Offshore Arctic Oil and Gas Market Report to 2018,” business intelligence provider Infield Systems analyzed current and future offshore oil and gas developments within the Arctic Circle and in the three major “sub-Arctic” areas: Sakhalin Island offshore Russia, offshore Eastern Canada in Newfoundland and Labrador, and the Cook Inlet in Alaska. The company defines sub-Arctic as areas that exhibit Arctic-like conditions, i.e., ice-prone, but are outside the Arctic Circle.

“In a nutshell, our analysis of the Arctic indicates that active Arctic development is still several years away,” Edward Richardson, analyst for Infield Systems, said. “Our analysis indicates that offshore developments in the heavily ice-prone Arctic are general still many years from fruition. Operators are primarily focused on building the capabilities and expertise that will be critical to tapping the potentially vast resources locked within the Arctic’s icy depths. Nevertheless, in established Arctic and sub-Arctic basins that exhibit more benign environments, such as Newfoundland and the Norwegian Barents, progress is likely to be more rapid with new projects such as ExxonMobil’s Hebron and Eni’s Goliat currently leading the way.”

Calling it one of last large, underexplored areas, Mr Richardson said rising oil prices in recent years had a twofold impact on the Arctic. “It has gradually become the new frontier for oil and gas operators, but the problem is that, as oil prices rise, they also unlock all sorts of other resources. That’s what we’ve really seen with the increasing challenges from tight oil and shale gas. I don’t think it’s a case of getting overly excited about the Arctic in the short term; it’s a case of looking at it as a very long-term play.”

Data from market intelligence provider Infield Systems indicate that more than 170 offshore fields have been discovered in the Arctic.

Global Data, another market intelligence provider, pointed specifically to the impact that shale has had on Arctic development. The largest field in the Russian sector of the Barents Sea, the Shtokman gas field, was originally planned to be developed as an LNG project for the American market, Anna Belova, lead upstream analyst – oil and gas, Global Data, said. “This was in 2007, and since then the shale revolution has really obliterated those plans because the current price of gas cannot support the capital expenditures that an LNG project in the Barents Sea will require.”

Infield Systems’ data suggests that the Arctic holds 136.6 billion barrels of oil equivalent in discovered proven and probable offshore reserves, and a 2008 US Geological Survey report indicated that there could be an additional 346 billion barrels of oil equivalent undiscovered. However, what will really drive market developments, Mr Richardson said, are economics and access, not necessarily the quantity of resources. “Russia’s Arctic has two of the world’s largest offshore gas fields. Since the discovery in the ‘80s, they’ve never been brought to development, and that’s largely because there were richer pickings onshore in Western and Central Siberia, which were much closer to pipeline infrastructure, that had fewer technical challenges and were consequently much cheaper to develop.”

Legislation, too, is imperative to encourage the industry that the time is right to drill. Operators face regulatory requirements for offshore Arctic exploration that often result in higher costs than conventional exploration, Mr Richardson continued. “The Gold Standard in the Arctic is to have two drilling rigs working in tandem during a drilling campaign. That way, if needed, a relief well can be drilled at very short notice – a key provision given the very rapid onset of winter ice.” This standard is currently in force in the most ice-prone environments, such as Canada’s high-arctic, off the North Slope of Alaska and offshore Greenland.

In a breakdown of capital expenditures for Arctic development from 2012 to 2018 by Infield Systems, the Norwegian Barents gets the largest slice of the pie at 37%.

Mr Richardson stressed, however, that right now the Arctic is mostly about building capabilities. “We’re really some way from an oil and gas boom in the offshore Arctic. Operators are now going about the slow process of building expertise and technological capability to operate in these environments, with a view to developing Arctic resources possibly seven or 10 years down the line. We saw the same process with deepwater.”

Capabilities needed include upgrading rig fleets to work year round, James Hearn, drilling analyst, Infield Systems, said. “So far, the rigs that you see on the market are more aimed toward sub-Arctic, where you don’t necessarily need the most advanced rig, whereas in the Arctic, companies are generally at the innovative, basic design stage. ”

Russia

According to a May 2013 report by Ernst & Young (EY), Russia is estimated to hold more than half of the world’s Arctic hydrocarbon resources. Russia’s Ministry of Natural Resources estimates in-country Arctic resources at 75 billion tons of oil equivalent, 70% gas and 30% oil, Olga Beloglazova, senior analyst with EY’s Moscow Oil & Gas Center, explained. “There’s nothing that’s equivalent to the potential of the Russian Arctic,” she said. The ministry has set a target for the country to produce 50 million to 60 million tons of oil equivalent from the Arctic shelf by 2030, which would be approximately 12% of estimated overall domestic output, she added.

The Russian Arctic remains mostly a virgin territory, she said, and current activity is still solely focused on seismic work. She believes Gazprom plans to drill the first exploration well by the end of this year in the Prirazlomnoye field in the Pechora Sea. Further, according to some estimates, 15 wildcat exploration wells – mostly in deepwater – will be drilled by 2017, and by 2020-2025 approximately 30 more will be drilled in deepwater. Costs for each well can range from US $50 million all the way to $400 million depending on depth, weather and geological data. “In the case of semisubmersibles, platforms and drillships, the costs rise to $300 to $400 million,” she said.

Ernst & Young estimates that Russia holds more than half of the world’s total Arctic hydrocarbon resources. “There’s nothing that’s equivalent to the potential of the Russian Arctic,” senior analyst Olga Beloglazova said.

To reach this level of development, Ms Beloglazova acknowledged, the country will need approximately 260 additional vessels, including platforms, tankers, LNG ships, ice-breakers and supply vessels.

Even if these vessels were delivered, other challenges abound. For example, exploration drilling in the Russian Arctic is severely limited by the availability of open-water periods, she said. “In many of Russia’s Arctic regions, it’s only operational a couple of months per year.”

Further, control of Russian Arctic projects is limited to state companies. “Because it is required for state companies to have experience in offshore operations not less than five years, only Rosneft and Gazprom meet such requirements,” Ms Beloglazova said. “At the moment, these companies have licenses practically for all the attractive blocks in the Arctic.”

So far this year, Rosneft has secured seven licenses in the Barents Sea alone, GlobalData’s Ms Belova said. “They were offered to Rosneft without an auction, so they’re not open for bidding. When you consider that LukOil, the largest independent private producer in Russia, has been unable to secure any licenses, it’s clear the trend is very much toward the state-associated companies for the development of the Arctic region in general and the Barents Seas in particular.” She believes this is unlikely to change anytime soon.

For IOCs, entering the Russian Arctic also requires partnering with Russian state-owned companies. Eni, ExxonMobil and Statoil each announced agreements with Rosneft during the International Economic Forum in St Petersberg in June, completing the contractual framework of their joint development projects. Eni and Rosneft have exploration activities in the Russian Barents Sea on the Fedynsky and Central Barents blocks. Statoil and Rosneft will explore offshore frontier areas in the Sea of Okhotsk and in the Barents Sea, and ExxonMobil’s agreement includes a joint venture for projects in the Kara Sea and other potential joint ventures to explore seven additional licenses in the Russian Arctic.

In most Arctic regions of the world, exploration drilling is severely limited by the availability of open-water periods. Many of Russia’s Arctic regions are operational for only a couple of months a year.

The Russian government is also working on making investments more attractive, Ms Belova said. “The federal government is really trying to develop the Arctic region by providing a temporary exemption or holiday from the mineral extraction tax (MET), which is analogous to royalties. For offshore projects located north of the Arctic Circle, the MET is not assessed on the first 35 million tons of produced crude, subject to license length requirements.” Additionally, there has been a suspension of export duty for difficult-to-develop fields. “The duty varies with the price of the benchmark Urals crude and is set by the Russian authorities at US $54.67/bbl for September 2013, so not having to pay that for the first four or five years that a project operates can provide significant economic incentive.”

Russian companies are eager to add new reserves as well. “On the company level, most companies have been producing old assets developed or discovered during the Soviet times, so there’s a drive for them to increase their valuation by acquiring new reserves, and they have not yet been able to do so as successfully as some Western IOCs,” Ms Belova said.

Once the first development is completed, however, project are expected to move forward at a more accelerated pace. “That’s what we saw in East Siberia, for example. It’s an extremely remote, extremely hard-to-operate region, thousands of miles away from markets. But after 10 years of intensive development, midstream infrastructure investments and fiscal incentives, the first large production hubs, such as Vankor, Talakanskoye and Verkhnechonskoye, are in place. New assets are now brought into production in as little as three years.”

Parker Drilling, which has had continuous operations in Russia for 15 years, helped its customer drill the world’s longest well, Odoptu OP-11, with the Yastreb land rig from Sakhalin Island for Exxon Neftegas Ltd (ENL). The well reached a total measured depth of 40,502 ft and set a world record for extended-reach drilling (ERD). The well was drilled from the island to an offshore bottomhole location. Following the OP-11 success, Parker also supported the most recent extended-reach drilling world record of 40,602 ft on ENL’s Z-44 well at the Chayvo field on Sakhalin Island in 2012.

Oil and gas production in the Barents Sea has increased significantly since 2007. The resolution in 2010 of a long-standing dispute over how to divide the Barents Sea and parts of the Arctic Ocean between Russia and Norway also has opened the way for more exploration.

The company notes it is proud of these significant milestones using ERD technology, and Mr Collins said he believes that ERD in such applications will become an increasingly important part of the E&P solutions mix, particularly in arctic environments. “ERD has important implications, especially in those areas where weather, ice and challenging sea conditions present significant technical and environmental risk. This makes land-based rigs for ERD applications a favorable development option as they have the potential to reduce the need for multi-drill site locations as the technology can cover greater and greater distances. This will allow E&P companies to tap reserves that otherwise would not have been reachable without building new platforms.”

The major E&Ps are confident there is tremendous potential in Arctic exploration, he added, but the associated costs and operational challenges to tap this potential are substantial. “We believe the lessons learned through the successful ERD drilling achievements in the Russian Arctic regions can be applied to help reduce the need for offshore drilling and open up land-based drilling year round versus seasonal offshore drilling programs. The success of E&P work on Sakhalin demonstrates the Arctic can be drilled in a safe and environmentally effective manner.”

Although Parker Drilling has been operating in the Arctic region of Alaska since the mid-1960s, in Russia since 1991, and on Sakhalin Island for 15 years, the company formally established an Arctic Business Unit earlier this year, Mr Collins said. The company currently provides operations and maintenance services on Sakhalin Island with the Orlan platform located offshore, as well as the Yastreb land rig. The company is also providing technical advisory, operations and maintenance services for another platform being constructed by a local operator and recently mobilized an additional rig to the Sakhalin region. Last year, Parker renewed a five-year operations and maintenance agreement with ENL, assuring the company’s continued presence in Russia’s Arctic drilling environment.

Rigs built for Arctic conditions

Statoil is the most active player in the Barents Sea by number of active exploration blocks.

In addition to the myriad operational, technological and economic challenges, industry feels the weight of environmental responsibility for Arctic drilling. To efficiently meet that responsibility, Stena Drilling built the Stena IceMAX, a dynamically positioned, dual-mast ice-class drillship, at Samsung Heavy Industries in South Korea.

“Stena IceMAX was the first drillship built achieving Polar Class 4 for the hull and thrusters. Essentially she has a strengthened hull and propellers, which can sustain ice loading,” Eirik Reinertsen, marketing & business development manager for Stena Drilling, said. The rig, delivered in 2011, was enhanced with large boilers for heating, a hot seawater wash-down system for snow and ice on the decks, heated walkways and helideck, large provision storerooms, large bunker capacity, zero-discharge systems for liquids on the rig and technology for exhaust gas cleaning. The vessel also carries two six-ram BOPs to provide 100% redundancy, he said; it is capable of drilling in water depths up to 10,000 ft, drilling to depths of 35,000 ft and has Knuckleboom deck cranes rated to -30°C.

The Stena IceMAX was enhanced for Arctic operations with large boilers for heating, a hot seawater wash-down system for snow and ice on the decks, heated walkways and helideck, large provision storerooms, large bunker capacity, zero-discharge systems for liquids on the rig and technology for exhaust gas cleaning.

Although the rig is currently operating for Shell in French Guiana in a non-Arctic project, Stena Drilling continues to work on improvements for Arctic operations through the development of ATMOS, a detachable mooring system that allows for mooring of the vessel in shallow waters between 60 and 100 meters depending on weather. The system, which the company has been developing since 2008, increases the operating window for conventional drillships and allows for quick disconnect in case of emergency so the vessel would be able to move off quickly while maintaining full well control, Mr Reinertsen said.

The company also has three DrillMAX class drillships – the Stena DrillMAX, Stena Carron and Stena Forth – which were built for harsh environments and can work in Arctic areas. Although their hulls have not been strengthened for working in ice, they were built to comply with Norwegian regulations for working in the Barents Sea and has winterization features. The Stena Forth and the Stena Don semisubmersible worked in the Arctic during the 2010 summer season, drilling exploration wells for Cairn Energy offshore Greenland. “Our contracts vary in length, but we see three to five years as the norm – especially for units targeted for the Arctic as these units require significant investment,” he said. The Stena DrillMAX is currently on a one-year contract in Ghana with Hess, the Stena Carron is in Canada on a two-year contract with Chevron, and the Stena Forth is in the Gulf of Mexico on a three-year contract for Hess.

NordAq Energy kicked off a drilling program in the Cook Inlet in 2010. It drilled its first well in the Tiger Eye Central prospect last year and recently finished a second well. Anakema will be the next prospect, with potential for six additional wells at Shadura.

Anchorage-based independent NordAq Energy expects to invest approximately $280 million to drill its Alaskan acreage from now through 2016, with hopes of tapping into “missing giants” among the potential 30 billion barrels of oil and 180 trillion cu ft of gas that the US Geological Survey estimates could remain in the Arctic Alaska province. The company estimates the hydrocarbon potential in its Cook Inlet holdings could be as high as 1 tcf of gas and 550 million bbl of oil, according to NordAq CEO Paul Devine. A drilling program there kicked off in 2010, and the company drilled its first well in the Tiger Eye Central prospect last year and recently finished a second well. The next focus area will be the Anakema prospect, and six additional wells may be drilled at the Shadura prospect, where the company made its first gas discovery in 2011.

“There has been a lot of good geology and reservoir engineering built up over the last few decades in Alaska… Our confidence is high that we will continue to make discoveries,” Mr Devine explained, noting that NordAq holds 360,000 acres and some 57 leases across Alaska. “It’s very important we maintain an active drilling program to gain really meaningful data.”

NordAq Energy says its Cook Inlet prospects are located approximately three miles from a network of underutilized pipelines. The existing infrastructure would enable them to access the LNG plant, Tesoro-Alaskan Refinery and the Agrium Fertilizer plant.

In the Cook Inlet alone, the company has more than 47,000 onshore acres over three groups of leases: Tiger Eye Central, Shadura and Anakema. An October 2011 report by the US Geological Survey estimated the undiscovered mean resource potential of the Cook Inlet Basin at 0.6 billion bbl of oil and 20 tcf of gas.

“The feature of Alaskan geology is that prospects are sometimes stacked, so with a single well you can explore multiple horizons, and that excites us as a small company with limited resources,” Mr Devine said. The company is currently conducting gas-flow tests from its discovery well in Tiger Eye Central and expects to begin drilling its much-larger North Slope acreage by Q1 2014. Right now the company has one rig working in the Cook Inlet and expects to add a second next year, subject to receiving necessary permits. NordAq also is working toward having a third rig operational, possibly as soon as next year, for its North Slope drilling program.

“In the Cook Inlet, you have an LNG plant that could again ship LNG to Japan, a fertilizer plant which needs gas and an ever-growing need for existing infrastructure to provide utilities. It’s a nice mix of domestic and an international market. There’s an increasing appetite for gas and a price that is significantly higher than the Lower 48,” Mr Devine said. Whereas Henry Hub prices are around $3.40/mcf, natural gas is being contracted on the southern Alaska peninsula at prices between $6.50 to $7.50 per mcf. “Prices started rising as a result of falling supply capability, hence increased drilling activity and support by state subsidy,” he added.

Technology fit for the Arctic

In March, a major operator signed a US $3 million deal to deploy riserless mud recovery (RMR) services from AGR Enhanced Drilling offshore Sakhalin, Russia, during this year’s summer drilling season in water depths of approximately 100 meters. RMR provides a closed-loop circulation system for top-hole drilling before BOP/riser installation, enabling zero discharge to the sea and helping to improve borehole stability and optimize drilling and casing plans. The technology has been used to drill approximately 200 wells worldwide, according to the company.

“Using a heavier mud was not a good option due to environmental requirements in Russia, so our client employed RMR to avoid hole instability problems while drilling a 20-in. top hole at zero discharge,” Ramzy Rezk, regional sales manager for Enhanced Drilling, said. In Russia overall, the service has been used to drill five top holes offshore Sakhalin, saving on average nine days of rig time per hole, Mr Rezk said.

RMR also helps to reduce risks while drilling the top-hole section since most Russian Arctic concessions are still being explored for the first time; allowing operators to drill multiple wells at a time also helps with the short drilling season. “Russia has opened a new era in Arctic offshore field development and will require more subsea completion/production technology. Most of these concessions are new and need more studies and exploration,” Mr Rezk said. “Russian companies are getting licenses in areas like the Magadan region, Kara Sea, Black Sea and Barents Sea. These developments are going to deeper waters of 100 to 400 meters with more challenges. In such conditions, it is hard to predict the risks while drilling top holes.”

Stena Drilling also has three DrillMAX class drillships – the Stena DrillMAX (pictured), Stena Carron and Stena Forth – that were built for harsh environments and can work in Arctic areas.

Premium connections also are providing technological solutions for Arctic operations. Traditional dopes can freeze in low temperatures, complicating handling and installation. When fresh dope is applied before running the pipe, chemicals and heavy metals that might be present in these lubricants also could impact the environment.

Tenaris’ Dopeless technology was developed to address such challenges. “Nowadays, almost every premium connection that we sell in the Arctic Circle tends to have Dopeless coating applied,” Tomás Castiñeiras, Dopeless technology development director for Tenaris, said. He noted that the company has sold more than 13 million feet of premium connections with Dopeless around the world. “Currently, 30% of our sales of premium connections with this technology is destined to operations in the Arctic.”

The dry coating, which is applied to TenarisHydril premium connections in the mill, provides corrosion protection and serves as a lubricant without needing to reapply additional compounds. The technology was developed in 2001 in response to a request from ConocoPhillips in Norway for a dope-free connection, then launched in July 2003 in the North Sea and run in 2004 in the Barents Sea in Statoil’s Snøhvit project. The coating has been tested under 40°C and up to 250°C.

“We are joining from 500 to 1,000 connections per well and, in an offshore operation or places like continental Russia and Alaska, you cannot prepare these connections at the service base because it’s far from the rig’s location. So all this preparation has to be done at the rig site, and in the winter it’s quite complex,” Mr Castiñeiras said.

“Risk is increased, and the handling and disposal of slurries is more difficult when operating in -30/-40°C conditions. With frozen dope, a simple, low-risk operation like the removal becomes very complicated. I have seen operations where the pipe is light on fire to heat it and melt the dope, so you can imagine the impact.” Connections with Dopeless arrive at the rig site ready to run.

Halliburton, Gazprom Neft to collaborate on new technologies

Halliburton has entered into an agreement of cooperation with Gazprom Neft for the introduction of new technologies to improve operational efficiency in fields operated by the operator, the companies announced in August.
The two companies will collaborate on technological solutions for hard-to-recover reserves, unconventional resources, deepwater and other projects. Gazprom Neft specialists will provide Halliburton with updated data on implementation of specific projects, and Halliburton experts will offer technological solutions.

“According to our estimation, more than half of all our oil will be produced using innovative technologies,” Gazprom Neft first deputy general director Vadim Yakovlev said. “Enhancement of mature field development efficiency and implementation of new major projects involve technological challenges. In order to solve these problems, we are actively cooperating with Russian and foreign service companies choosing the most suitable modern technologies for our oilfields.” Gazprom Neft hopes to increase hydrocarbon production to 100 million tons of oil equivalent by 2020.

Alaska

Tenaris’ Dopeless coating was developed in 2001 in response to a request from ConocoPhillips in Norway for a dope-free connection.

Offshore operations targeting the Alaskan Arctic have seen some setbacks over the past year. ConocoPhillips announced in April that it was suspending its 2014 plans to drill in Alaskan Arctic waters due to uncertainties over federal regulatory and permitting standards, and Shell last year removed two drilling rigs, the Kulluk and the Noble Discoverer, from Alaska’s Chukchi and Beaufort Seas. The drill barge and drillship have since been sent to Asia for maintenance and repairs. Shell, which has spent more than $4.5 billion on its exploration program, called off its drilling program for 2013.

Onshore Alaska, in contrast, appears to be entering a renewed era of investments. BP is one of the largest oil producers in the state, and BP-operated oilfields account for two-thirds of Alaska’s total oil production, Greg Mattson, BP Alaska region VP of wells, said. The company operates 13 oilfields on the Alaska North Slope, including Prudhoe Bay, which is still the largest field in North America after 36 years of production, recently surpassing 12 billion barrels of cumulative production.

Today BP has seven onshore rigs in its Alaska fleet and plans to add two more by 2016. These additions are part of an announcement the company made in June to add $1 billion in new investment to its North Slope operations over the next five years. The announcement came soon after Alaskan Gov. Sean Parnell signed the so-called More Alaska Production Act. The state, which depends on oil production to fund 90% of its budget revenues, is hoping to spur production by eliminating tax rate calculations that changed monthly under the old tax regime. Alaska’s oil tax system is now built around a 35% base rate, with tax incentives tied directly to new oil production.

Pipes with Dopeless sit in snow in Hammerfest, Norway, (top) and in Sault Ste. Marie in Canada (below). The technology is applied to its premium connections in the mill; they arrive at the rig site ready to run.

“BP has a long commitment to Alaska and to America’s energy security. The Alaska tax change is an important step forward and will help BP’s Alaska business compete for more investment. In 2007, Alaska implemented an aggressive oil tax, and the business climate became very challenging. Industry investments were going to locations like the Gulf of Mexico or North Dakota that had more competitive opportunities. North Slope oil production is one-third of its peak of 2 million bbl/day in the 1980s,” Mr Mattson said. “As a package, this legislation was an important step forward and put Alaska back in the game.”

He continued: “The oil tax reform in Alaska drew an immediate investment response from industry. BP will add the two rigs and 200 jobs on the North Slope. The $1 billion over five years will result in increased well work and drilling activity equaling 30 to 40 additional new wells or sidetracks annually.

In addition, we were able to secure support from the Prudhoe Bay working interest owners for the initial assessment phase of additional development projects totaling $3 billion.” BP will add the first rig in 2015 and the second in 2016.

The improved tax structure also allows BP to focus on the development of Alaskan gas, Mr Mattson said. “The Alaska gas resource is significant. Now is the right time to analyze whether it is economic to produce this resource. BP is part of a multi-company team that launched summer fieldwork in June. Gathering this information is important to evaluate the major engineering commitments that will be required in the future.” The field studies are part of a joint project team effort led by ExxonMobil. The 2013 summer field season includes land surveying, hydrology and fisheries surveys, cultural and subsistence surveys and wetlands mapping.

Besides economic incentives, drilling technology advances also continue to contribute to improved production in Alaska. “BP uses a suite of advanced drilling technologies that have reduced surface footprint and increased recovery rates. These include multilateral wells, horizontal drilling, coiled tubing and extended-reach drilling,” he said. Enhanced oil recovery technologies also have helped to double the estimated life of Prudhoe Bay, the company believes.

Mr Mattson noted that one of BP’s success stories this year was the application of multistage hydraulic fracturing to a low-permeability formation known as the Sag River reservoir. “The Sag is a shallow, thin reservoir, which overlies the main Prudhoe Bay producing sands. This type of fracturing utilizes a series of fracture sleeves that are opened sequentially by dropping graduated sized balls to slide the sleeves. This allows multiple stimulations to be pumped efficiently in one operation rather than in several steps. The Sag proof-of-concept well placed six hydraulic fractures, staged along the 6,700-ft horizontal wellbore in 15- to 18-ft thick sand.”

“We’ve learned a lot in from the decades of operating in Alaska’s remoteness and its extreme yet environmentally sensitive region. BP continues to work with its drilling contractors to deliver safe and reliable operations in this sensitive environment,” Mr Mattson said.

From a drilling contractor’s perspective as well, the Alaskan market is looking up. Nabors, which has been operating in the state since 1963, hopes the new tax regime will shorten the time between exploration and production. “Alaska is a whole different scale of operation, but things have been pretty slow up there since 2008. Now that’s changed, and there are a lot of plans being made by the major operators to get back to work, so we’re pretty optimistic about the future,” Denny Smith, director of corporate development & investor relations for Nabors, said.

The company currently operates 17 high-spec rigs in the onshore Arctic. Typical contracts range from one to three years, and dayrates vary from $40,000 to $80,000 for existing rigs but are trending upward as activity restores and can be much higher given the increasing capital requirements, according to Mr Smith.

Rigs operate for BP in Alaska’s Prudhoe Bay in different seasons. BP is one of the largest oil producers in the state, and its operated oil fields account for two-thirds of total Alaska production.

He noted that Arctic drilling, both onshore and from offshore islands, is a lot like offshore drilling. The footprint is compact, and wells are on very tight centers. Most of the land rigs are actually built in a cantilever configuration like an offshore jackup, but on wheels, he explained. “The drilling itself is pretty standard, but the logistical and environmental challenges can make operations more difficult and very expensive. The technology is also very costly. You wouldn’t do it if it were not for the magnitude of the reserves.”

Parker Drilling recently built two newly designed Arctic-class drilling rigs commissioned in December 2012 with Rig 273 and in February this year with Rig 272. The rigs are specifically designed to reliably perform in the harsh, environmentally sensitive North Slope region while meeting new levels of performance in terms of safety and ecological care. “Our new arctic rigs in Alaska are fully enclosed mobile systems, making them more comfortable and efficient for our personnel to operate while also supporting our environmental protection goals, Mr Collins said. “For example, the rigs feature a design enclosure with secondary spill containment to control potential spills inside the rig.” Other features that address the high-risk conditions of the North Slope include freeze protection redundancy, advanced top drive controls, pipe handling and mobilization systems; all to ensure safer rig moves and operational efficiency for our customer.

BP plans to add $1 billion in investments to its operations there, including bringing two more drilling rigs to its North Slope fields over the next five years.

Norway: Barents Sea

In April 2010, Russia and Norway resolved a 40-year-old dispute over how to divide the Barents Sea and part of the Arctic Ocean into clear economic zones extending to the edge of Europe’s northern continental shelf. This resolution opened the way for both countries to more actively explore for and develop the area’s resources. Based on the 2009 US Geological Survey, the Norwegian East Barents province potentially contains 7.5 billion barrels of crude, 321.3 trillion cu ft of gas and 1.1 billion barrels of natural gas liquid.

In Norway’s recently concluded 22nd licensing round, 20 new licenses were issued in the country’s Southern

Barents Sea to 29 participating companies while only four new licenses were issued for the Norwegian Sea, Joseph Gatdula, senior upstream analyst – oil & gas for GlobalData, said “The high interest in the Barents gives you an indication of how that compares with the other areas of the Norwegian sector.” A total of 13 exploration wells will be drilled in the Barents Sea by the end of this year, he added.

The first license block offered in the Barents Sea dates back to 1981, but with other areas generating more interest in the Northern North Sea and in the Norwegian Sea, fewer blocks have been taken throughout that period. Of the 118 licenses granted since 1981 in the Barents, 23 licenses were granted just this year. “More recently there’s been greater interest because of the fact that most of the large discoveries within the existing areas of the North Sea and Norwegian Sea have been discovered. So this new unexplored area has lots of potential to provide the same types of billion barrel-plus reserves. People are looking for those large monster fields that can really change a company.”

Norway is expected to open a 23rd licensing round next year introducing a previously unlicensed area of the East Barents, Mr Gatdula said, and that’s where the majority of potential reserves are believed to be located. “I would expect a tremendous amount of interest from companies in that area if that licensing round opens up.”

The Drill Module on Parker Drilling’s Arctic-class Rig 272 begins its journey from Deadhorse, Alaska, to its first drilling location. The rig was designed to perform in the harsh, environmentally sensitive North Slope.

In the Norwegian sector of the southern Barents Sea, three rigs are currently drilling: the West Hercules, the Leiv Eiriksson and the Transocean Arctic, with options through 2017, 2019 and 2015, respectively, Mr Gatdula said. Statoil chartered Seadrill’s West Hercules semi for an exploration program, TOTAL contracted Ocean Rig’s Leiv Eiriksson semi, and the Transocean Arctic is being used by Rig Management Norway representing a consortium of operators, Mr Gatdula said. Average dayrates for these units run between $423,000 to $520,000, he added.

As industry considers investments in the Norwegian Barents Sea, Mr Gatdula believes that there will be a continued trend toward joint ventures. “It would be a big risk on their part to be a sole operator of a field, risking anywhere from $1 billion to $10 billion on a field. Oil majors will play a significant role in all fields, but it’s about diversifying that risk and lowering single-field development costs.” Costs challenges will be further compounded by the fact that there is still little to no infrastructure in the Barents. “In the case of the Snøhvit field, it also cost approximately $1.4 billion for just the wells and the subsea tieback option that they used. Other costs included for Statoil were 89 miles of multiphase unprocessed pipeline and systems with umbilicals from the subsea development to an onshore terminal, with processing facilities that cost an additional $6.3 billion,” he said.

Significant investments in infrastructure will be required before more fields can be brought online. “Whether it’s ports to handle ships, whether it’s pipelines, whether it’s new airports… there’s going to be large capital commitment. In today’s climate, there may be better opportunities in other parts of the world that will be significantly less in terms of the initial development costs and risk, like areas in West Africa or offshore Brazil.”

Comparisons between the more mature areas and for less-developed areas, however, aren’t always direct. Brazil, for example, has a five-year expected E&P budget of US $240 billion for one company while the total expected budget for the Barents Sea over the next five years is $20 billion, Mr Gatdula said. “This disparity is because the more mature areas have projects ready for funding, and economic discoveries have been made and exploration methodology and targets are well defined,” unlike a less mature area like the Barents Sea, where the exploration strategies are less clear. “(The Arctic) is going to be much more expensive than probably every other place in the world to operate,” he continued. “But there are very few areas that are so underexplored that have the potential to provide one of those giant fields so, for these companies to take these risks, the probable gains are worth it.”